System and method for a water cooling pump

ABSTRACT

A method and a system are provided for a deep well pump system having a high volume lift of hot or very hot fluids. In an embodiment, a high volume high temperature deep well pumping system uses an external source of cooling fluid to keep one or more vulnerable pumping apparatus components at an acceptable operating temperature. In an embodiment, the cooling fluid, after cooling the component(s), is released into the production fluid flow stream from the pump and both fluids are lifted back up to the surface. In an embodiment, a return tubing, line, or pipe can bring the cooling water back to the surface or other location with or without mixing it with the production fluid.

FIELD OF INVENTION

The present invention relates to a system and method for a deep well pump. More specifically, the present invention relates to a system and method for a cooling apparatus in the deep well pump. The well pump may involve the pumping of any sort of fluid, e.g., oil, water, etc., and the cooling entity may be any sort of appropriate fluid, e.g., water, etc.

BACKGROUND

Current systems for deep well pumping involve electrical submersible pumps (“ESPs”) or geared centrifugal pumps (“GSPs”). Such pumps are the current, principal methods used as artificial lifts in high rate oil wells, where a multi-stage centrifugal pump is located downhole. For example, in an ESP system, a downhole electrical motor directly drives the pump, with electric power supplied to the motor via a cable extending from the surface to the motor's location downhole. For example, in a GSP system, the pump is driven via a rotating rod string extending from the surface to a speed increasing transmission system located downhole. The speed increasing transmission system is used to increase the relatively slow rotation of the rod string to a much faster rotation, as needed by the pump. In this example, the rod string is driven by an electric motor situated at the surface.

These current systems, used in the recovery of, e.g., fluids and/or quasi-fluids, experience undesired thermal effects. For example, the temperature of the produced fluid in thermally stimulated oil wells exceeds the operating temperature limits of ordinary downhole pumping systems. For low to moderate productivity wells, the GSP or sucker rod pumping system can be used, provided certain changes in the metallurgy of the downhole components are made. However, such rod pumping systems are incapable of handling highly productive wells. At present, an electric submersible pump (ESP) is the only practical option available. However, the high produced fluid temperatures are particularly severe for a pump system. Also, ESPs have a high voltage electric motor, as well as insulated cable downhole, exposed to temperatures that can exceed 500 degrees Fahrenheit. A mere change in the metallurgy does not cure the high temperature situation. Some systems have increased the operating limit of the downhole electrical components of the ESP system to about 400 degrees Fahrenheit. However, those high temperature systems are expensive and not highly reliable. Accordingly, there exists a need for a reliable, reasonable-cost high temperature system for high volume lift of fluid or quasi-fluid.

In FIG. 1, a normal temperature ESP system 100 is shown having a production pipe 101 connected to a wellhead 102, which is essentially connected to a casing or housing 104 which surrounds and protects downhole elements the system 100. Power 103 is fed to the system via a power cable 107 which runs inside the casing 104 to power the motor 111, e.g., an electric motor. The motor 111 is located downhole in the system. The motor 111 drives the pump 108 above it. A motor protector 110 is connected between the motor 111 and the pump 108. The motor protector 110 consists of seals and pressure compensators that work to keep fluid out of the motor 111. The pump 108, e.g., a multi-stage centrifugal pump which runs at ˜3500 RPM, is located directly above the motor 111 and motor protector 110. At the lower end of the pump 108, there is a pump intake section 109 which has pump vents or holes. The tubing 105 attaches to the top of the pump and forms the flow conduit for the pressurized well fluid to travel to the surface. Cable straps 106 are used to hold the tubing 105 and the power cable 107 inside the ESP well casing 104. In operation, the motor 111 is supplied electric current via the power cable 107 that extends from the surface to the pump 108. The motor 111 drives the pump 108 to lift well fluid out to the surface. At the surface, the well may be equipped with a wellhead having valves and piping to transmit the well fluid to a collection facility or other location.

FIG. 2 shows a more detailed view of the downhole components and the flow of fluid 200 according to the ESP system 100 of FIG. 1. The formation fluid enters the perforations in the casing 104 located below the motor 111. This formation fluid flows toward the pump intake or inlet 109 via the annular space between the motor and the well casing. This well fluid flow cools the motor 111, which is needed for the operation of the ESP system. Otherwise, the motor 111 would rapidly overheat and fail. After passing by and cooling the motor 111, the well fluid flows into the pump inlet 109 and is pressurized by the multiple pump stages and then flows into the tubing at the outlet of the pump 108. The pump 108 increases the pressure of the fluid to a level such that it can flow via the tubing 105 to the surface.

As shown in FIG. 2, cable straps 106 are used to hold the power cable 107, which delivers power to the motor, in place with the pump 108 and motor protector 110.

In FIG. 3, a normal temperature GCP system 300 is shown having a production pipe or flow line 303 essentially connected to a casing or housing 305 which surrounds and protects downhole elements of the system 300. Inside the casing, typical elements such as a rod drive string 302 is run inside a tubing 301 to the GCP transmission assembly 304. A pump 305 is located just below the GCP transmission assembly 304, through which the tail end 306 of the tubing 301 is run. The fluid enters via openings in the casing 305 and are drawn into the tubing tail end 306, and then pumped up to the surface via the tubing 301.

Generally, for an electrical submersible pump to handle a high temperature or a very high temperature, significant modifications in the construction and materials used, e.g., in the motor and electrical cable, must be made. For example, the materials used in the seals and the bearings in the motor protector are specialized for high temperature service. The pressure compensators for balancing the pressure between the interior of the motor and the wellbore are made to have a much larger capacity in order to handle the large temperature variations, and are constructed of a high temperature material. Such modifications results in a much more expensive, less efficient, and possibly less reliable high temperature electrical submersible pump than a normal temperature electrical submersible pump. Presently, while the maximum operating temperature for such high temperature electrical submersible pumps is about 425° F., the recommended continuous operating temperature is significantly less.

Accordingly, a need exists for a system and method of a reliable, cost and time efficient electrical submersible pump which can handle high temperature situations.

The geared centrifugal pump (GCP), for example, as described in U.S. Pat. No. 5,573,063, is, like the ESP, a high volume deep well pumping apparatus. A schematic of a typical normal temperature installation is provided as FIG. 3. Since all downhole components of the GCP are purely mechanical and principally fabricated from steel alloy, the GCP is more easily adapted to very high temperature than an ESP. Nonetheless, temperatures greater than 500° F. tax the strength and durable of even high temperature steel alloys, and employing the cooling technique described above on a GCP would allow for a less expensive and more reliable pumping system that a conventionally configures GCP adapted to very high temperature operation.

As shown in FIG. 3, a normally configured GCP consists of a multi-stage centrifugal downhole pump driven by a rotating rod string via a speed increasing transmission. The formation fluid enters the pump intake, usually equipped with a tubing tail as shown and is increased in pressure by the multi-stage centrifugal pump. The high-pressure fluid flows through the transmission assembly via conduits to the tubing at the top end, then on to the surface. The flow conduits passing along side the transmission gear train, but within the pressure housing of the transmission, allows the produced fluid to effectively cool the transmission. The conduits are thin walled D-shaped tubes, whose internal flow pressure is kept in equilibrium with the internal pressure of the transmission via a pressure compensator.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows an example of an electrical submersible pump.

FIG. 2 shows a detailed pump illustration of an electrical submersible pump according to FIG. 1.

FIG. 3 shows an example of a geared centrifugal pump.

FIG. 4 shows a water cooled electrical submersible pump according to an embodiment of the present invention.

FIG. 5 shows a detailed view of a water cooled electrical submersible pump having an internal power cable according to an embodiment of the present invention.

FIG. 6 shows a detailed view of a water cooled electrical submersible pump having an internal power cable according to an embodiment of the present invention.

FIG. 7 shows a detailed view of a water cooled electrical submersible pump having an external power cable according to an embodiment of the present invention.

FIG. 8 shows a water cooled geared centrifugal pump according to an embodiment of the present invention.

FIG. 9 shows a detailed view of a water cooled geared centrifugal pump according to an embodiment of the present invention.

DETAILED DESCRIPTION

Embodiments of the present invention provide for a relatively easy to install and maintain artificial lift pump for use in oil and water pump systems. More specifically, embodiments of the present invention may be used for deep well pumping of oil, water, or other fluid/quasi-fluid.

Embodiments of the present invention provide for a deep well pump system having a high volume lift of very hot fluids. Further embodiments of the present invention provide for a deep well pump system which uses some components of available normal temperature electrical submersible pumps to provide a more efficient and less expensive system than current high temperature electrical submersible pumps.

Embodiments of the present invention provide for a high volume deep well pumping system adapted to high temperature use by using an external source of cooling fluid to keep the vulnerable pumping apparatus components at an acceptable operating temperature.

Embodiments of the present invention provide a method to cool one or more vulnerable components by using a conduit from the surface carrying the cooling fluid, the fluid effectively cooling the components. In further embodiments, the fluid is ejected into the flow stream from the pump and lifted back up to the surface. In an alternative embodiment, a return line brings the cooling water back to the surface with or without mixing it with the production fluid.

FIG. 4 shows an example embodiment of a water cooled electrical submersible pump according to the present invention. For example, an externally cooled bottom intake ESP may be provided. In FIG. 4, at the bottom end or downhole part of the pump system 400, the system 400 includes a tubing tail pump intake extension 415 that is equipped with a packer 414 which isolates the perforated casing from the above situated unperforated casing. The tubing tail 415 is attached to the intake of the multi-stage centrifugal pump 413, and allows communication between the pump intake and the perforated casing below the packer 414, so that formation fluid entering the casing 405 through the perforations can flow into the pump inlet. Directly above the pump 413 is a motor protector 408, and the motor 410, e.g., an electric motor, which drives the pump 413. For example, the motor 410 and protector 408 are housed inside of a motor shroud 409, which is then attached to the tubing 406 which extends to the surface. The electrical power for the motor 410 is supplied by a power cable 404 which is run inside the tubing 406 to the motor 410, or alternatively is run alongside the tubing 406. Cable or other material attachments 407 can be used to strap or hold the power cable 404 to the tubing 406. At the top of the pump system 400, e.g., at the surface, the well may be equipped with a wellhead 402 which may allow a supply of cold water 401 to be pumped down the tubing 406 and through the motor 410 and motor protector 408 and then out through the cooling water outlet 411, and which may allow the production flowline 403 and valve(s) to carry the produced fluid flowing out of the pump outlet 412 and up the tubing casing annulus to the appropriate facilities/destination(s).

FIG. 5 shows a detailed view of a water cooled electrical submersible pump 500 having an internal power cable according to an embodiment of the present invention. In FIG. 5, the hot formation fluid enters the formation through the perforations 515 in the casing 505 and flows into the tail end of the tubing 506 and into the pump inlet, above the packer. The pressure of this formation fluid is increased by the multi-stage centrifugal pump 513. The resulting high-pressure fluid flows into the casing annulus 505 through the outlet 512 at the top of the pump 513. The packer 514 is needed to isolate the perforated well bore from the high-pressure pump outlet 512. The pressure inside the well opposite the perforations is at a much lower pressure than that at the pump outlet 512 so that fluid will flow from the formation into the well. The high-pressure fluid then flows to the surface through the casing tubing annulus and into the flow line at the wellhead.

In an embodiment, the tubing 506, which may be used in the normal temperature electrical submersible pump systems as the conduit for the high-pressure formation fluid to flow to the surface, is used in this high temperature electrical submersible pump system to transport cooling water from the surface to the motor 510, e.g., electric motor, and protector 508 downhole. This cooling water flows down the tubing 506 into the shroud 509 surrounding the motor 510 and protector 508, along the shroud-motor annulus, and out the cooling water outlet 511 shown. This water very effectively cools the motor 510 and protector 508, allowing the use of normal temperature components. Also, as shown in FIG. 5, the power cable 504 to the motor 510 is run inside the tubing 506 and kept at normal temperatures by the cooling water, eliminating the need for a specialized high temperature cable. FIG. 5 shows the internal cable 504 coupled to or strapped 516 to a string of rods 507 to both, e.g., support the cable during pulling, but also provide a stiffness to stab the cable 504, e.g., a flat cable, into a wet-connection 517 at the top of the motor 510. The water then flows into the well annulus to join the pump outlet fluid and which then flows to the surface. Since in most thermal applications, the majority of the formation fluid pumped to surface is water, adding a relatively small additional amount of water to the well stream provides a negligible operational effect.

In an embodiment of the present invention—whether an ESP, GCP, or other system—the tubing carrying the cooling water must be insulated, as it is immersed in produced water and/or oil that can have a high temperature, e.g., a temperature as high as 500° F. If the tubing is not insulated, the cooling water will reach ambient temperature, e.g., ˜500° F. if that is the temperature of the produced or formation fluid, by the time the cooling water reaches the pump and thus provide no cooling effect. For example, in an embodiment, in an about 1500 foot deep well, if the about 1500 feet of about 2⅞″ tubing is fitted with a layer of insulation of about 0.6 inch thick with an R factor of 30, then about 250 bpd of cooling water with a temperature of about 60° Fahrenheit may reach the downhole equipment at a temperature of less than about 160° F., which will very effectively cool the motor. The R factor being a known measure of an insulation's ability to keep heat in or heat out. The higher the R factor, the better it works as a barrier, and possibly the thicker the insulation. For example, if a smaller about 2⅜″ tubing is used with an about 0.8″ layer of similar insulation, the about 60° F. input water may reach the downhole motor with a temperature of about 120° F.

In an embodiment of the present invention, the amount of water required to effectively cool the motor is small compared to the amount of fluid pumped to surface by the pump and motor in a well pump system. For example, assuming the motor is putting about 100 horsepower (HP) into the pump, and the motor and power cable efficiency is about 75%, then power cable must deliver about 133 HP of electrical power to the motor. The about 33 HP that does not go into the pump as mechanical power is instead converted into heat by the motor and cable, and equals, in this example, about 2.7 million British thermal units (BTUs) per day. The about 100 HP of motor input into a pump of average efficiency lifts about 3000 barrels per day of fluid from about 1500 feet depth. The about 1500 feet depth is normal for thermal stimulated oil pools.

For example, if about 250 barrels per day (bpd) of cooling water were injected down the tubing of a pump system embodiment according to the present invention, the amount of heat generated by the motor would raise the temperature of the cooling water 31° F. In the situation discussed above, if about 250 bpd of about 60° F. water is injected down about 1500 feet of insulated about 2⅞ inch tubing, the water would reach the motor at a temperature of about 165° F. and be heated to 196° F. as it cools the motor. This temperature is a reasonable operating temperature for available ESP motors. Therefore, the cooling water needed to keep the motor and cable at temperatures within normal design range represents only about an 8% additional volume. The additional energy required to pump the cooling water is also minor. The amount of pressure drop down 1500 feet of 2⅞″ tubing is less than 5 pounds per square inch (psi), so the principal power required to inject the about 250 barrels per day (bpd) of cooling water is that needed to increase the cooling water from atmospheric pressure to that of the produced fluid flow line pressure. For example, a typical flow line pressure can be 150 psi, and the power needed to pump about 250 bpd of water at about 150 psi is less than about 1 HP, a negligible amount.

In the specific examples described herein, as well as those that can be contemplated, these apply for ESP, GCP and other pump systems including for the water cooling embodiment of the present invention. Further, different types of motors can be used in the pump systems. Electric motors and their power cables are described herein for purposes of example, but embodiments of the present invention are not limited to use of such motors.

In FIG. 6, a detailed view of a water cooled electrical submersible pump 600 having an internal power cable according to an embodiment of the present invention is shown. FIG. 6 shows an alternative embodiment to that shown in FIG. 5, by using a round armored cable instead of the flat cable. In this example, the power cable 604 is internal, i.e., located within the tubing 606. The round cable 604 is sufficiently stiff to allow a wet stab-in connection 613. A string(s) of wireline 614, for example, can be strapped around the cable 604 and/or rod string for reinforcement and/or to provide tensional support during pulling of the cable 604 in and out of the well hole. In an embodiment, the power cable 604 is run down the well hole after the pump assembly 611, 609 has been run and set in the well. The use of a rod string with the cable strapped to it allows for a relatively flexible cable to be run to bottom and stabbed into a wet connection 613 at the top of the motor 608 in an embodiment of the present invention. Further, running the cable 604 inside insulated tubing 606 to keep temperatures cool is an embodiment of the present invention.

In FIG. 6, the hot formation fluid enters the formation through the perforations 615 in the casing 605 and flows into the tail end of the tubing 606, e.g., insulated tubing, and into the pump inlet, above the packer 612. The pressure of this formation fluid is increased by a pump 611, e.g., a multi-stage centrifugal pump. The resulting high-pressure fluid flows into the annulus of the casing 505 through the outlet 609 at the top of the pump 611. The packer 612 is needed to isolate the perforated well bore from the high-pressure pump outlet 609. The pressure inside the well opposite the perforations is at a much lower pressure than that at the pump outlet 609 so that fluid will flow from the formation into the well, or pump system in the well. The high-pressure fluid then flows to the surface through the casing 605 and into the production flowline at the wellhead.

In an embodiment, the tubing 606 is used in this high temperature electrical submersible pump system to transport cooling water from the surface to the motor 608, e.g., electric motor, and protector 607 downhole. This cooling water flows down the, e.g., insulated, tubing 606 into the shroud 616 surrounding the motor 608 and protector 607, along the shroud-motor annulus, and out the cooling water outlet 610 shown. This water cools the motor 608 and protector 607, allowing the use of normal temperature components. Further, the power cable 604 to the motor 608 is run inside the tubing 606 and is kept at normal temperatures by the cooling water, eliminating the need for a specialized high temperature cable. The water then flows into the well annulus to join the pump outlet fluid which then all flows to the surface.

FIG. 7 shows an alternative configuration of a high temperature externally cooled ESP 700 which includes an external power cable according to an embodiment of the present invention. In FIG. 7, the hot formation fluid enters the formation through the perforations 715 in the casing 705 and flows into the tail end of the tubing 706 and into the pump inlet, above the packer 714. The pressure of this formation fluid is increased by the pump 713, e.g., a multi-stage centrifugal pump such as a 513 Series Pump. The resulting high-pressure fluid flows into the casing annulus 705 through the pump outlet 712 at the top of the pump 713. The packer 714 is used to isolate the perforated well bore from the high-pressure pump outlet 712. The pressure inside the well opposite the perforations 715 is at a much lower pressure than that at the pump outlet 712 so that fluid will flow from the formation into the well and eventually up through the pump system. The high-pressure fluid then flows to the surface through the casing and into the flow line at the wellhead.

In an embodiment, tubing 706 is used in the high temperature electrical submersible pump system to transport cooling water from the surface to the motor 710, e.g., electric motor such as a 450 Series Motor, and protector 708, e.g., a 400 Series Protector, downhole. This cooling water flows down the tubing 706 into the shroud 709 surrounding the motor 710 and protector 708, along the shroud-motor annulus, and out the cooling water outlet 711. This water effectively cools the motor 710 and protector 708, allowing the use of normal temperature components. A power cable 704 to provide power to the motor 710 is run alongside the cooling water tubing rather than internally, i.e., inside the tubing 706. This configuration requires the power cable to be high temperature rated, i.e., manufactured such that it can be used in high temperature environments. For example, a flat #4 Hi-Temp armored cable could be used in an embodiment. The water then flows into the well annulus to join the pump outlet fluid and which then flows to the surface.

FIG. 8 shows a water cooled geared centrifugal pump (GCP) 800 which can be used in high temperature situations, e.g., in a deep well or hole and run at a similar speed to that for a normal temperature well, according to an embodiment of the present invention. In this embodiment, the tubing 806 is not used for the flow of the formation fluid to the surface as in a normal temperature GCP, but rather as the conduit for cooling water transmitted down from the surface, e.g., from a cooling water input line 802. In this embodiment, the GCP does not require a shroud to be placed around the transmission assembly, as there are already internal channels for the flow of fluid that very effectively allow cooling of the internal components by the circulating water.

In FIG. 8, a production pipe or production flow line 803 is connected to a casing or housing 805 which surrounds and protects downhole elements of the system 800. Inside the casing 805, elements such as a rod drive string 804 is run inside a tubing 806 to the GCP transmission assembly 808. A pump 811 is located just below the GCP transmission assembly 808, from which the tail end 813 of the tubing 806 is run. Below the tubing tail 813, the hot formation fluid enters via openings or perforations in the casing 805 and are drawn into or flows into the tubing tail end 813 and into the pump inlet, above the packer 812. Power for the GCP assembly 808 is provided by a power cable 807 which is run downhole in the tubing 806. Since the power cable 807 is run inside the tubing 806, the power cable does not need to be specially manufactured for high temperature operation. The formation fluid is run up through the tubing tail 813 to the packer 812 to the pump 811, the formation fluid then leaves the pump via the pump outlet 810. The cooling water, on the other hand, runs from the input line 802 at the surface down through the tubing 806 and passes through the GCP transmission assembly 808. The cooling water is exhausted via the cooling water outlet 809 into the produced fluid stream exiting the pump outlet 810, in a similar manner as for the electrical submersible pump embodiments of the present invention described herein.

Since the pressure of the hot formation fluid/quasi-fluid is increased by the pump 811, the resulting high-pressure fluid flows into the casing annulus 805 via the pump outlet 810 situated at the top of the pump 811. The packer 812 is used to isolate the perforated well bore from the high-pressure pump outlet 810. Effectively, the pressure inside the well opposite the perforations is at a much lower pressure than that at the pump outlet 812 so that the fluid will flow into the well and eventually up through the pump system. The high-pressure fluid then flows to the surface via the casing 805 and into the production flow line 803 at the wellhead, or other location desired.

FIG. 9 shows a detailed view of a water cooled geared centrifugal pump system according to an embodiment of the present invention. In this embodiment, the tubing 906 and GCP transmission assembly 908 are shown coated with thermal insulation 903. In this embodiment, the hot formation fluid is shown entering the well casing 905 and being drawn into the tubing tail to the packer 912. The formation fluid is then pumped, e.g., via a 513 Series Pump 911, up through the pump outlet 909 into the casing 905. In order to keep cool the GCP assembly 908 which runs the pump 911, cooling water or fluid is sent down through tubing 906 alongside the rod drive string 904 and is passed through the GCP assembly 908. The cooling water then is passed out the outlet 910 of the GCP assembly 908, and mixes with the pressurized by the pump formation fluid. The fluid then flows through the casing 904 to the surface or other destination. In an embodiments of the present invention, the cooling fluid may be water, or any other fluid appropriate for use with such equipment. Further, various types of models can be used for the GCP assembly, pump, cable, tubing, casing, and other features. Given the flow of a fluid in the pump system, when there is water present as a flow agent, it may be desirable to use water-resistant coated materials to prevent corrosion. Likewise, the same follows for use of other types of fluids.

It should be understood that there exist implementations of other variations and modifications of the invention and its various aspects, as may be readily apparent to those of ordinary skill in the art, and that the invention is not limited by specific embodiments described herein. Features and embodiments described above may be combined with and without each other. It is therefore contemplated to cover any and all modifications, variations, combinations or equivalents that fall within the scope of the basic underlying principals disclosed and claimed herein. 

What is claimed is:
 1. A fluid pump system for a well, comprising: a pump apparatus having a tubing extending from a cooling fluid provider to a motor apparatus, the motor apparatus having an outlet through which fluid can exit from the motor apparatus, wherein cooling fluid from the cooling fluid provider runs through the tubing and passes through the motor apparatus such that at least one of a temperature of any materials in the tubing and a temperature of the motor apparatus is affected.
 2. The fluid pump system of claim 1, wherein the temperature of the motor apparatus is decreased by the cooling fluid.
 3. The fluid pump system of claim 2, wherein the pump system is used for deep wells.
 4. The fluid pump system of claim 3, wherein the pump apparatus is one of a modified electrical submersible pump and a modified geared centrifugal pump.
 5. The fluid pump system of claim 3, wherein the pump apparatus has a pump driven by the motor apparatus to pressurize any well production fluid entering the pump from the well, wherein the resulting pressurized well production fluid is lifted up together with the cooling fluid in the well casing and outside the tubing to a top surface of the well.
 6. The fluid pump system of claim 3, wherein the cooling fluid is lifted up in a separate tubing device to one of a top surface of the well and the tubing extending from the cooling fluid provider.
 7. The fluid pump system of claim 5, wherein the cooling fluid is water.
 8. The fluid pump system of claim 5, further comprising a power cable for providing energy to the motor apparatus is run through the tubing, wherein a temperature of the power cable being decreased when in contact with the cooling fluid.
 9. The fluid pump system of claim 5, further comprising a power cable for providing energy to the motor apparatus is run outside of the tubing and inside the fluid pump system, wherein the power cable is made of a high temperature resistant material.
 10. A fluid pump method, comprising: transmitting a cooling fluid through a tubing from an upper level of a deep well pumping system to a motor of the deep well pumping system; cooling by the cooling fluid the motor of the deep well pumping system as the cooling fluid passes through the motor; leaving by the cooling fluid from the motor into a well casing of the deep well pumping system; lifting the cooling fluid from the well casing to the upper level of the deep well pumping system, wherein the cooling fluid is lifted to the upper level of the deep well pumping system with any pressurized well fluid, the pressurized well fluid having been pressurized by a pump of the deep well pumping system, the pump being driven by the motor.
 11. The fluid pump method of claim 10, wherein the cooling fluid cools a temperature of at least one element disposed within the tubing.
 12. The fluid pump method of claim 11, wherein the at least one element disposed within the tubing is at least one of a rod string and a power cable.
 13. The fluid pump method of claim 11, wherein the cooling fluid is water and the pressurized well fluid is at least one of water and oil.
 14. The fluid pump method of claim 11, wherein the cooling fluid is lifted to the upper level of the deep well pumping system in a separate cavity than the pressurized well fluid.
 15. The fluid pump method of claim 11, further comprising: separating the pressurized well fluid from the cooling fluid at the upper level of the deep well pumping system, so that any desired and undesired fluids are transported to their respective proper destinations.
 16. The fluid pump method of claim 11, wherein the deep well pumping system includes components of one of a geared centrifugal pump and an electric submersible pump, and that any tubing extending from an upper surface of the deep well pumping system to the motor is used as a conduit for the cooling fluid. 